Detection of islanded behavior and anti-islanding protection of a generator in grid-connected mode

ABSTRACT

A method of controlling a generator system connected to an electric power system in which the output frequency characteristic of the generator system is measured, a first phase angle and frequency of the measured frequency characteristic is estimated using a first phase locked loop having a first bandwidth, and a second phase angle and frequency of the measured frequency characteristic is estimated using a second phase locked loop having a second bandwidth greater than the first bandwidth. Further, the method calculates a frequency difference between the first and second estimated frequencies, and an angle variation that is proportional to the calculated frequency difference. The estimated second phase angle is then added to the calculated angle variation so as to form an output current phase angle reference, and an output current phase angle of the generator system is controlled to be aligned with the output current phase angle reference. The method also determines whether or not the generator system is within a generation island based on the measured frequency characteristic.

CROSS-REFERENCE TO A RELATED APPLICATIONS

This application is a divisional of U.S. application Ser. No.09/975,148, filed Oct. 12, 2001 now U.S. Pat. No. 6,815,932, whichclaims the benefit of U.S. Provisional Application No. 60/240,153, filedOct. 12, 2000, each of which is incorporated herein by reference in itsentirety.

FIELD OF THE INVENTION

The present invention relates to controlling a generator systemconnected to an electric power system so as to avoid the unintentionalislanding of the generator. More particularly, the present inventionrelates to actively detecting generation islands using a combination offrequency characteristic thresholds, and an active phase angledestablization technique to destablize well or perfectly matchedislands.

BACKGROUND OF THE INVENTION

Many businesses, manufacturing companies, homeowners, etc. usegenerators in addition to power delivered by the local electric powercompany (also referred to as an electric power system or utility grid).However, non-utility owned generator systems connected to an electricpower system create both operational and maintenance problems.

The operational problems include a non-utility owned generator systemnot being synchronized with a de-energized power grid included in theelectric power system. The lack of synchronism between the non-utilityowned generator system and the electric power system cause a higher thannormal voltage across open isolation devices included between thenon-utility owned generator and the electric power system, as well ashigher than normal current flow when the isolation devices are closed.The higher than normal voltages across the opened isolation devicesdamages the devices and the higher than normal current flows tend toprematurely open over-current protection devices associated with thenon-utility owned generator system and the electric power system.

Maintenance problems include personnel inadvertently contacting portionsof the electric power system which are energized from the non-utilityowned generator system. This is a severe problem which often results ininjury or even death. For example, during a severe winter storm, utilitycompanies have to dispatch emergency crews throughout neighborhoods torepair downed transmission lines, etc. To safely repair the downedlines, isolation devices corresponding to a power grid including thedowned transmission lines are intentionally opened so the downed linesand associated transmission components are de-energized. However, if ahomeowner plugs in a portable generator system to provide electricityfor his family, for example, the power from the portable generatorsystem may be fed back into the de-energized power lines, transformersetc, critically injuring a maintenance worker.

To avoid these types of possibly fatal injuries, the utility companywould have to manually isolate all portable generator systems, etc.,connected to the local grid requiring maintenance so as to bring thevoltage to a safe level before beginning any maintenance work. This isextremely ineffective and time-consuming. In fact, it is virtuallyimpossible to know when and where every portable generator system willbe used. Thus, the power companies require generator systems connectedto the utility grid to include protective devices.

SUMMARY OF THE INVENTION

The present invention is directed to solving the above and other notedproblems.

To solve these problems, the present invention provides a novel methodof controlling a generator system connected to an electric power systemin which an output current phase angle of the generator system isvaried, and an output frequency characteristic of the generator systemis measured. Further, the method determines whether or not the generatorsystem is within a generation island based on the measured frequencycharacteristic

In another method, the output frequency characteristic of the generatorsystem is measured, a first phase angle of the measured frequencycharacteristic is estimated using a first phase locked loop having afirst bandwidth, and a second phase angle of the measured frequencycharacteristic is estimated using a second phase locked loop having asecond bandwidth greater than the first bandwidth. Further, a phaseshift between the estimated first and second phase angles is calculated,and the method determines whether or not the generator system is withina generation island based on the calculated phase shift.

In still another method, the output frequency characteristic of thegenerator system is measured, a first phase angle and frequency of themeasured frequency characteristic is estimated using a first phaselocked loop having a first bandwidth, and a second phase angle andfrequency of the measured frequency characteristic is estimated using asecond phase locked loop having a second bandwidth greater than thefirst bandwidth. Further, the method calculates a frequency differencebetween the first and second estimated frequencies, and an anglevariation that is proportional to the calculated frequency difference.The estimated second phase angle is then added to the calculated anglevariation so as to form an output current phase angle reference, and anoutput current phase angle of the generator system is controlled to bealigned with the output current phase angle reference. The method alsodetermines whether or not the generator system is within a generationisland based on the measured frequency characteristic.

The present invention also provides novel computer program productscoded to execute the above methods within a generator system.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete appreciation of the present invention and many of theattendant advantages thereof will be readily obtained as the samebecomes better understood by reference to the following detaileddescription when considered in connection with the accompanyingdrawings, wherein:

FIG. 1A is perspective view, partially in section, of an integratedturbogenerator system.

FIG. 1B is a magnified perspective view, partially in section, of themotor/generator portion of the integrated turbogenerator of FIG. 1A.

FIG. 1C is an end view, from the motor/generator end, of the integratedturbogenerator of FIG. 1A.

FIG. 1D is a magnified perspective view, partially in section, of thecombustorturbine exhaust portion of the integrated turbogenerator ofFIG. 1A.

FIG. 1E is a magnified perspective view, partially in section, of thecompressorturbine portion of the integrated turbogenerator of FIG. 1A.

FIG. 2 is a block diagram schematic of a turbogenerator system includinga power controller having decoupled rotor speed, operating temperature,and DC bus voltage control loops.

FIG. 3 is an overview of a generator system included in a grid-connectedsystem configuration;

FIG. 4 is a schematic diagram illustrating a generation island within asite containing a generator system;

FIG. 5 is a schematic diagram illustrating a generation islandencompassing portions of an electric power system as well as operatingsites;

FIG. 6 is a schematic diagram illustrating a Phase Locked Loop forsynchronizing a generator system with an electric power system;

FIG. 7 is a graph illustrating voltage and current phase angles of agenerator island comprising a generator system and associated loads;

FIG. 8 is a graph illustrating a relationship between a maximum phasesensitivity and quality factor of a resonant load;

FIG. 9A is a flow chart illustrating a first example of generationisland detection methods according to the present invention;

FIG. 9B is a flow chart illustrating a second example of detectionmethods according to the present invention; and

FIG. 10 is an overview of an electric power system and connected sitesfor illustrating voltage phase swings during normal operation.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The present invention will be described with reference to aMICRO-TURBINE generator system manufactured and sold by Capstone TurbineCorporation. However, the present invention may also be implemented withother generator systems and distributed resources. Accordingly, prior todiscussing the detection methods according to the present invention, adescription of a turbogenerator system and corresponding powercontroller of a MICRO-TURBINE generator will be given with reference toFIGS. 1 and 2.

Mechanical Structural Embodiment of a Turbogenerator

With reference to FIG. 1A, an integrated turbogenerator 1 according tothe present invention generally includes motor/generator section 10 andcompressor-combustor section 30. Compressor-combustor section 30includes exterior can 32, compressor 40, combustor 50 and turbine 70. Arecuperator 90 may be optionally included.

Referring now to FIG. 1B and FIG. 1C, in a currently preferredembodiment of the present invention, motor/generator section 10 may be apermanent magnet motor generator having a permanent magnet rotor orsleeve 12. Any other suitable type of motor generator may also be used.Permanent magnet rotor or sleeve 12 may contain a permanent magnet 12M.Permanent magnet rotor or sleeve 12 and the permanent magnet disposedtherein are rotatably supported within permanent magnet motor/generatorstator 14. Preferably, one or more compliant foil, fluid film, radial,or journal bearings 15A and 15B rotatably support permanent magnet rotoror sleeve 12 and the permanent magnet disposed therein. All bearings,thrust, radial or journal bearings, in turbogenerator 1 may be fluidfilm bearings or compliant foil bearings. Motor/generator housing 16encloses stator heat exchanger 17 having a plurality of radiallyextending stator cooling fins 18. Stator cooling fins 18 connect to orform part of stator 14 and extend into annular space 10A betweenmotor/generator housing 16 and stator 14. Wire windings 14W exist onpermanent magnet motor/generator stator 14.

Referring now to FIG. 1D, combustor 50 may include cylindrical innerwall 52 and cylindrical outer wall 54. Cylindrical outer wall 54 mayalso include air inlets 55. Cylindrical walls 52 and 54 define anannular interior space 50S in combustor 50 defining an axis 51.Combustor 50 includes a generally annular wall 56 further defining oneaxial end of the annular interior space of combustor 50. Associated withcombustor 50 may be one or more fuel injector inlets 58 to accommodatefuel injectors which receive fuel from fuel control element 50P as shownin FIG. 2, and inject fuel or a fuel air mixture to interior of 50Scombustor 50. Inner cylindrical surface 53 is interior to cylindricalinner wall 52 and forms exhaust duct 59 for turbine 70.

Turbine 70 may include turbine wheel 72. An end of combustor 50 oppositeannular wall 56 further defines an aperture 71 in turbine 70 exposed toturbine wheel 72. Bearing rotor 74 may include a radially extendingthrust bearing portion, bearing rotor thrust disk 78, constrained bybilateral thrust bearings 78A and 78B. Bearing rotor 74 may be rotatablysupported by one or more journal bearings 75 within center bearinghousing 79. Bearing rotor thrust disk 78 at the compressor end ofbearing rotor 76 is rotatably supported preferably by a bilateral thrustbearing 78A and 78B. Journal or radial bearing 75 and thrust bearings78A and 78B may be fluid film or foil bearings.

Turbine wheel 72, Bearing rotor 74 and Compressor impeller 42 may bemechanically constrained by tie bolt 74B, or other suitable technique,to rotate when turbine wheel 72 rotates. Mechanical link 76 mechanicallyconstrains compressor impeller 42 to permanent magnet rotor or sleeve 12and the permanent magnet disposed therein causing permanent magnet rotoror sleeve 12 and the permanent magnet disposed therein to rotate whencompressor impeller 42 rotates.

Referring now to FIG. 1E, compressor 40 may include compressor impeller42 and compressor impeller housing 44. Recuperator 90 may have anannular shape defined by cylindrical recuperator inner wall 92 andcylindrical recuperator outer wall 94. Recuperator 90 contains internalpassages for gas flow, one set of passages, passages 33 connecting fromcompressor 40 to combustor 50, and one set of passages, passages 97,connecting from turbine exhaust 80 to turbogenerator exhaust output 2.

Referring again to FIG. 1B and FIG. 1C, in operation, air flows intoprimary inlet 20 and divides into compressor air 22 and motor/generatorcooling air 24. Motor/generator cooling air 24 flows into annular space10A between motor/generator housing 16 and permanent magnetmotor/generator stator 14 along flow path 24A. Heat is exchanged fromstator cooling fins 18 to generator cooling air 24 in flow path 24A,thereby cooling stator cooling fins 18 and stator 14 and forming heatedair 24B. Warm stator cooling air 24B exits stator heat exchanger 17 intostator cavity 25 where it further divides into stator return cooling air27 and rotor cooling air 28. Rotor cooling air 28 passes around statorend 13A and travels along rotor or sleeve 12. Stator return cooling air27 enters one or more cooling ducts 14D and is conducted through stator14 to provide further cooling. Stator return cooling air 27 and rotorcooling air 28 rejoin in stator cavity 29 and are drawn out of themotor/generator 10 by exhaust fan 11 which is connected to rotor orsleeve 12 and rotates with rotor or sleeve 12. Exhaust air 27B isconducted away from primary air inlet 20 by duct 10D.

Referring again to FIG. 1E, compressor 40 receives compressor air 22.Compressor impeller 42 compresses compressor air 22 and forcescompressed gas 22C to flow into a set of passages 33 in recuperator 90connecting compressor 40 to combustor 50. In passages 33 in recuperator90, heat is exchanged from walls 98 of recuperator 90 to compressed gas22C. As shown in FIG. 1E, heated compressed gas 22H flows out ofrecuperator 90 to space 35 between cylindrical inner surface 82 ofturbine exhaust 80 and cylindrical outer wall 54 of combustor 50. Heatedcompressed gas 22H may flow into combustor 54 through sidewall ports 55or main inlet 57. Fuel (not shown) may be reacted in combustor 50,converting chemically stored energy to heat. Hot compressed gas 51 incombustor 50 flows through turbine 70 forcing turbine wheel 72 torotate. Movement of surfaces of turbine wheel 72 away from gas moleculespartially cools and decompresses gas 51D moving through turbine 70.Turbine 70 is designed so that exhaust gas 107 flowing from combustor 50through turbine 70 enters cylindrical passage 59. Partially cooled anddecompressed gas in cylindrical passage 59 flows axially in a directionaway from permanent magnet motor/generator section 10, and then radiallyoutward, and then axially in a direction toward permanent magnetmotor/generator section 10 to passages 98 of recuperator 90, asindicated by gas flow arrows 108 and 109 respectively.

In an alternate embodiment of the present invention, low pressurecatalytic reactor 80A may be included between fuel injector inlets 58and recuperator 90. Low pressure catalytic reactor 80A may includeinternal surfaces (not shown) having catalytic material (e.g., Pd or Pt,not shown) disposed on them. Low pressure catalytic reactor 80A may havea generally annular shape defined by cylindrical inner surface 82 andcylindrical low pressure outer surface 84. Unreacted and incompletelyreacted hydrocarbons in gas in low pressure catalytic reactor 80A reactto convert chemically stored energy into additional heat, and to lowerconcentrations of partial reaction products, such as harmful emissionsincluding nitrous oxides (NOx).

Gas 110 flows through passages 97 in recuperator 90 connecting fromturbine exhaust 80 or catalytic reactor 80A to turbogenerator exhaustoutput 2, as indicated by gas flow arrow 112, and then exhausts fromturbogenerator 1, as indicated by gas flow arrow 113. Gas flowingthrough passages 97 in recuperator 90 connecting from turbine exhaust 80to outside of turbogenerator 1 exchanges heat to walls 98 of recuperator90. Walls 98 of recuperator 90 heated by gas flowing from turbineexhaust 80 exchange heat to gas 22C flowing in recuperator 90 fromcompressor 40 to combustor 50.

Turbogenerator 1 may also include various electrical sensor and controllines for providing feedback to power controller 201 and for receivingand implementing control signals as shown in FIG. 2.

Alternative Mechanical Structural Embodiments of the IntegratedTurbogenerator

The integrated turbogenerator disclosed above is exemplary. Severalalternative structural embodiments are known.

In one alternative embodiment, air 22 may be replaced by a gaseous fuelmixture. In this embodiment, fuel injectors may not be necessary. Thisembodiment may include an air and fuel mixer upstream of compressor 40.

In another alternative embodiment, fuel may be conducted directly tocompressor 40, for example by a fuel conduit connecting to compressorimpeller housing 44. Fuel and air may be mixed by action of thecompressor impeller 42. In this embodiment, fuel injectors may not benecessary.

In another alternative embodiment, combustor 50 may be a catalyticcombustor.

In another alternative embodiment, geometric relationships andstructures of components may differ from those shown in FIG. 1A.Permanent magnet motor/generator section 10 and compressor/combustorsection 30 may have low pressure catalytic reactor 80A outside ofannular recuperator 90, and may have recuperator 90 outside of lowpressure catalytic reactor 80A. Low pressure catalytic reactor 80A maybe disposed at least partially in cylindrical passage 59, or in apassage of any shape confined by an inner wall of combustor 50.Combustor 50 and low pressure catalytic reactor 80A may be substantiallyor completely enclosed with an interior space formed by a generallyannularly shaped recuperator 90, or a recuperator 90 shaped tosubstantially enclose both combustor 50 and low pressure catalyticreactor 80A on all but one face.

Alternative Use of the Invention Other than in Integrated Turbogenerator

An integrated turbogenerator is a turbogenerator in which the turbine,compressor, and generator are all constrained to rotate based uponrotation of the shaft to which the turbine is connected. The inventiondisclosed herein is preferably but not necessarily used in connectionwith a turbogenerator, and preferably but not necessarily used inconnection with an integrated turbogenerator.

Turbogenerator System Including Controls

Referring now to FIG. 2, a preferred embodiment is shown in which aturbogenerator system 200 includes power controller 201 which has threesubstantially decoupled control loops for controlling (1) rotary speed,(2) temperature, and (3) DC bus voltage. A more detailed description ofan appropriate power controller is disclosed in U.S. patent applicationSer. No. 09/207,817, filed Dec. 8, 1998 in the names of Gilbreth,Wacknov and Wall, and assigned to the assignee of the presentapplication which is incorporated herein in its entirety by thisreference.

Referring still to FIG. 2, turbogenerator system 200 includes integratedturbogenerator 1 and power controller 201. Power controller 201 includesthree decoupled or independent control loops.

A first control loop, temperature control loop 228, regulates atemperature related to the desired operating temperature of primarycombustor 50 to a set point, by varying fuel flow from fuel controlelement 50P to primary combustor 50. Temperature controller 228Creceives a temperature set point, T*, from temperature set point source232, and receives a measured temperature from temperature sensor 226Sconnected to measured temperature line 226. Temperature controller 228Cgenerates and transmits over fuel control signal line 230 to fuel pump50P a fuel control signal for controlling the amount of fuel supplied byfuel pump 50P to primary combustor 50 to an amount intended to result ina desired operating temperature in primary combustor 50. Temperaturesensor 226S may directly measure the temperature in primary combustor 50or may measure a temperature of an element or area from which thetemperature in the primary combustor 50 may be inferred.

A second control loop, speed control loop 216, controls speed of theshaft common to the turbine 70, compressor 40, and motor/generator 10,hereafter referred to as the common shaft, by varying torque applied bythe motor generator to the common shaft. Torque applied by the motorgenerator to the common shaft depends upon power or current drawn fromor pumped into windings of motor/generator 10. Bi-directional generatorpower converter 202 is controlled by rotor speed controller 216C totransmit power or current in or out of motor/generator 10, as indicatedby bi-directional arrow 242. A sensor in turbogenerator 1 senses therotary speed on the common shaft and transmits that rotary speed signalover measured speed line 220. Rotor speed controller 216 receives therotary speed signal from measured speed line 220 and a rotary speed setpoint signal from a rotary speed set point source 218. Rotary speedcontroller 216C generates and transmits to generator power converter 202a power conversion control signal on line 222 controlling generatorpower converter 202's transfer of power or current between AC lines 203(i.e., from motor/generator 10) and DC bus 204. Rotary speed set pointsource 218 may convert to the rotary speed set point a power set pointP* received from power set point source 224.

A third control loop, voltage control loop 234, controls bus voltage onDC bus 204 to a set point by transferring power or voltage between DCbus 204 and any of (1) Load/Grid 208 and/or (2) energy storage device210, and/or (3) by transferring power or voltage from DC bus 204 todynamic brake resistor 214. A sensor measures voltage DC bus 204 andtransmits a measured voltage signal over measured voltage line 236. Busvoltage controller 234C receives the measured voltage signal fromvoltage line 236 and a voltage set point signal V* from voltage setpoint source 238. Bus voltage controller 234C generates and transmitssignals to bi-directional load power converter 206 and bi-directionalbattery power converter 212 controlling their transmission of power orvoltage between DC bus 204, load/grid 208, and energy storage device210, respectively. In addition, bus voltage controller 234 transmits acontrol signal to control connection of dynamic brake resistor 214 to DCbus 204.

Power controller 201 regulates temperature to a set point by varyingfuel flow, adds or removes power or current to motor/generator 10 undercontrol of generator power converter 202 to control rotor speed to a setpoint as indicated by bi-directional arrow 242, and controls bus voltageto a set point by (1) applying or removing power from DC bus 204 underthe control of load power converter 206 as indicated by bi-directionalarrow 244, (2) applying or removing power from energy storage device 210under the control of battery power converter 212, and (3) by removingpower from DC bus 204 by modulating the connection of dynamic brakeresistor 214 to DC bus 204.

Under normal conditions, the turbogenerator system 2 is running inparallel with other synchronous generators within the electric powersystem and a magnitude and phase angle of the output current ofturbogenerator system 2 has little impact on the frequency and phaseangle of the voltage at the point of connection (POC) of the generator.However, when the turbogenerator system 2 is not running in parallelwith other synchronous generators within the electric power system, oris within a generation island, several problems occur.

For example, FIG. 3 illustrates generator system 302 connected inparallel to utility grid 308 so as to power local loads 304. Further,generator 302 and local loads 304 are connected to the utility grid 308via a distribution transformer 306.

When installed in this fashion, the power generated by generator system302 is supplied to local loads 304 only when a voltage from utility grid308 is present. That is, generator system 302 senses a loss of voltageduring utility grid voltage interruptions, and disconnects from utilitygrid 308 and local loads 304. When the utility grid voltage returns towithin specified limits, generator system 302 may be programmed torestart and recommence supplying power to the connected local loads 304.

Further, electric power companies commonly require that protectiverelaying devices be installed with generators connected to the grid. Theprimary purpose of the protective relaying devices is to ensure thatutility wires de-energized by the electric power company will not beenergized by generator system 302 (or any number of other non-utilityowned generator systems). Historically, the protective relaying deviceshave been relays or solid state power analyzers that provide controlsignals to disconnecting relays.

A current problem existing with generator systems operating in agrid-connected mode occurs when generator system 302 continuallysupplies power to a de-energized utility grid. The continued operationof generator system 302 often results in the formation of a generationisland in which a portion of the utility grid, not under utilitycontrol, remains energized while isolated from the remainder of theutility system.

For example, FIG. 4 illustrates generator system 310 in grid-connectedmode to electric power system 326. Also shown are two isolation devices318 and 330 situated between source of generation system 325 withinelectric power system 326 and generator system 310. Electric powersystem 326 provides power to two different sites 322 and 324, forexample, but generally supplies power to many different sites. Firstsite 322 includes generator 310 and load 312, which are connected toelectric power system 326 via isolation devices 318 and 330. Second site324 includes load 314 and is connected to electric power system 326 viaisolation device 330.

The example in FIG. 4 illustrates first isolation device 318 being open,which may occur because of a power surge from electric power system 330,etc. Thus, because opened isolation device 318 is between a point ofconnection (POC) 316 of generator system 310 and a point of commoncoupling (PCC) 320 of first site 322 and electric power system 326,generation island 328 is formed. Further, generation island 328 iscontained within first site 322 where generator system 310 is installed.

FIG. 5 illustrates another example in which first isolation device 318is closed, but second isolation device 330 is opened. Second isolationdevice 330 may intentionally be opened so maintenance personnel maybegin work on malfunctioning power lines, transformers, etc. Forexample, a tree limb may fall onto an overhead power line during astorm, which requires maintenance personnel to remove the tree limb. Inthis scenario, second isolation device 330 may intentionally be open bythe electric power company. Second isolation device 330 may alsoautomatically open if a power surge, etc., is detected.

Further, because second opened isolation device 330 is beyond PCC 320,generation island 328 will include parts of electric power system 326(such as power lines, transformers, etc.) and possibly other sitesserved by electric power system 326 (such as second site 324).

The sustained existence of generation islands 328 shown in FIGS. 4 and 5creates substantial operational and maintenance problems. Theoperational problems include a lack of synchronism between electricpower system 326 and generator system 310, which as discussed abovecauses a higher than normal voltage across open isolation devices 318,330, and higher than normal current flow when the isolation devices areclosed. The higher than normal voltage across the opened devices damagesthe devices and the higher than current flow tends to open over currentprotection devices prematurely.

A variety of protective devices use passive schemes to detect islandingconditions so as to prevent a generator system from sustaining anunintentional island. The passive schemes measure electrical variablesat the POC or PCC and detect conditions that indicate an island has beenformed.

For example, one detection method includes measuring a voltage value (orcurrent value) at the output of the generator (i.e., at the POC of thegenerator), and determining if the measured voltage value exceeds alower or upper voltage threshold for a specified period of time. Thevoltage thresholds and time period are generally stored within a memorycontained in a process controller of the generator. If the measuredvalues reach or exceed either the lower or upper voltage thresholds forthe set time period, the generator system can be immediately shut downto avoid the sustainment of a generation island.

In addition, in a poorly matched generation island, the output generatorvoltage generally reaches or exceeds the lower or upper voltagethresholds. That section normally contains substantially more loads thanthe connected non-utility owned generator systems. A poorly matchedisland often occurs when a utility company de-energizes a power grid,because the de-energized power grid contains a significant number ofloads.

However, the passive schemes are insufficient in detecting well matchedor perfectly matched islands. In more detail, an island may be wellmatched or perfectly matched if the total power output by the generatorsystem substantially equals the power required by the load(s). That is,a well matched generation island is one where the real power from thegenerator system can be delivered to an islanded load without exceedingthe lower or upper voltage thresholds.

For example, if electric motors form a substantial fraction of theislanded load, then the electric motors are capable of generating enoughpower to support the voltage in the island for a few cycles. In thisinstance, a poorly matched island may appear well matched until theelectric motors are no longer able to support the voltage in the island.Thus, in this instance, the detection of the generation island by thepassive schemes will be delayed.

In addition, the impedance magnitude and phase angle of the output powerfrom the generator system are often non-linear functions of the voltagein the generation island. Examples of non-linear loads include electricmotors and loads that trip or drop-out on under voltages. Thesenon-linear loads can increase the probability of an island beingwell-matched.

Further, the passive protection features are very sensitive todisturbances on the electric power system, such as voltage sags, surges,etc. Thus, the protection features often trip on voltage sags, surges,switching transients and successful “instantaneous” reclosure events. Acomplete shutdown of the generator system for all of these cases isinefficient.

In addition, the time period at which passive schemes detect generationislands varies and is typically more than 10 cycles of a nominal supplyfrequency and in some cases may be greater than 10 seconds. Theselengthy time periods contribute to the maintenance problems discussedabove.

In addition, as noted above, under normal conditions the generatorsystem is running in parallel with other synchronous generators withinthe electric power system and a magnitude and phase angle of the outputcurrent of generator system has little impact on the frequency and phaseangle of the voltage at the point of connection (POC) of the generatorsystem.

In more detail, a generator system in a grid-connected mode utilizes aPhase Locked Loop (PLL) to create an internal angle reference that inthe steady state has the same frequency and phase as the voltagemeasured at the POC. For example, FIG. 6 illustrates PLL structure 340configured to provide such a feedback process.

As shown, PLL 340 include low pass filter 342, angle and frequencymeasurement components 341, 344, phase correction gain component 348,integrator 352, adder 350 and subtractor 346. Low pass filter 342 hasunity gain for DC signals, and thus angular frequency estimate 358output by PLL 340 will be exact when a frequency of the electric powersystem is constant (or varying very slowly). Further, angle estimate 354output by PLL 340 is formed by integrating angular frequency estimate358 via integrator 352. The values output by PLL 340 (i.e., angleestimate 354 and angular frequency estimate 358) are used so thegenerator system produces the substantially the same frequency and phaseas the voltage measured at POC 316.

That is, when the frequency of the electric power system is constant (orvarying very slowly), angle estimate 354 will track the angle of thevoltage at POC 316, but may have a constant phase error due to theunknown constant of integration. Thus, to lock the outputs of PLL 340 inphase as well as in frequency a feedback loop is used. The feedback loopadjusts an input to integrator 352 according to an error between ameasured angle from measured angle component 344 and angle estimate 354via subtractor 346, phase correction gain 348 and adder 350. Inaddition, for PLL 340 to be stable, the input to integrator 352 isincreased if the measured angle from measured angle component 344 leadsestimated angle 354 and is reduced is the measured angle lags estimatedangle 354.

However, when a generation island is formed, the frequency and voltageangle at the POC are significantly affected by the magnitude and phaseangle of the current of the generator system. This phenomenon can bebest described with reference to FIG. 7.

In more detail, as shown in FIG. 7, the impedance phase angle φ_(Island)looking into the POC determines the phase angle between the generatorsystem voltage V_(POC-Island) and the current I_(POC-Island). This phaseangle is also affected by the generator system frequency. Further, thereal and reactive power demands required by the turbogenerator systemdetermine the phase angle δ between the generator system current andangle estimate 354 produced by PLL 340 included in the generator system.The fixed relationship between the angle estimate and the actual currentphase angle is ensured by the closed loop current control employed inthe generator system (i.e., by Bi-directional load power converter 206).

Referring again to FIGS. 6 and 7, PLL 340 will only reach a steadycondition when the angle estimate θ is aligned with the angle of themeasured voltages at the POC. Therefore, the generator system will becontained indefinitely in a perfectly matched island only if:φ_(Island)=δ  (1)

If the island is not perfectly matched, the angular frequency estimateproduced by PLL 340 will continue to increase and force the actualgenerator system output frequency to exceed the upper frequency tripthreshold or will continue to decrease and force the actual generatorsystem output frequency to exceed the lower frequency trip threshold.

Further, a perfectly matched generation island can only be sustained ifit represents a locally stable equilibrium point. The stability of aperfectly matched generation island may be examined using a perturbationanalysis. For example, assume a small increase is applied to angularfrequency estimate 358 in PLL 340, which results in an increase in thefrequency being applied to the islanded loads. If the impedance phaseangle φ_(Island) increases because the angular frequency estimate 358 isincreased, PLL 340 will tend to further increase angular frequencyestimate 358 so as to follow the increase in the voltage phase angle. Inthis case, the island will be unstable.

On the contrary, if the impedance phase angle φ_(Island) reduces becausefrequency estimate 358 is increased, PLL 340 will tend to reduce angularfrequency estimate 358 back towards the equilibrium point so as tofollow the decrease in the voltage phase angle. In this case, thegeneration island will be stable. Similar arguments apply to negativefrequency perturbations.

The stability of an island also depends upon the ability to changefrequency to reach a new equilibrium point when the current phase angleof the generator system changes. The sensitivity of the frequency tochanges in the generator system current phase angle is orders ofmagnitude greater in a perfectly matched island than it is when thegenerator system is operating in parallel with synchronous generators inthe electric power system.

In more detail, the frequency sensitivity of a perfectly matched islandis denoted G and is defined as follows: $\begin{matrix}{G = {\frac{1}{f_{POC}}{\frac{\mathbb{d}f_{POC}}{\mathbb{d}\phi_{Island}}}}} & (2)\end{matrix}$The frequency sensitivity G is basically a percentage change infrequency brought about from a small change in the current phase angleof the generator system. In addition, a lower bound of the frequencysensitivity represents a generation island that behaves most like anormal operating electric power system.

Regarding the lower boundary, the aggregate islanded load providing theleast frequency sensitivity is the one with the largest change inimpedance angle for a given change in frequency. For example, linearstable loads such as a parallel resonant circuit operating at thenatural resonant frequency provides the least sensitivity. Further, thesensitivity G falls as the quality (Q factor of the resonant load)increases. In more, detail, the natural resonant frequency and Q factorfor a parallel RLC circuit are defined as follows: $\begin{matrix}{{\omega_{n} = \frac{1}{\sqrt{LC}}}{Q = \frac{R}{\sqrt{\text{L}\text{/}\text{C}}}}} & (3)\end{matrix}$The impedance angle of a parallel RLC circuit and a derivative ofimpedance angle with respect to angular frequency can be expressed as afunction of angular frequency, as follows: $\begin{matrix}{{\phi_{Island}(\omega)} = {\frac{\Pi}{2} - {\tan^{- 1}\left( \frac{\omega/\omega_{n}}{Q\left( {1 - {\omega^{2}/\omega_{n}^{2}}} \right)} \right)}}} & (4)\end{matrix}$ $\begin{matrix}{\frac{\mathbb{d}\phi_{Island}}{\mathbb{d}\omega} = \frac{- \left( {1 + {\omega^{2}/\omega_{n}^{2}}} \right)}{\omega_{n}{Q\left( {1 + {\left( {{1/Q^{2}} - 2} \right){\omega^{2}/\omega_{n}^{2}}} + {\omega^{4}/\omega_{n}^{4}}} \right.}}} & (5)\end{matrix}$To place a lower bound on the frequency sensitivity G of a parallel RLCcircuit, it is convenient to place an upper bound on the phasesensitivity G_(inv) (i.e., the inverse of G) defined as follows:$\begin{matrix}{G_{inv} = {\frac{1}{G} = {{f_{POC}{\frac{\mathbb{d}\phi_{Island}}{\mathbb{d}f_{POC}}}} = {\omega{\frac{\mathbb{d}\phi_{Island}}{\mathbb{d}\omega}}}}}} & (6)\end{matrix}$As the above equation notes, G_(inv) is defined as the product of theangular frequency times the magnitude of the derivative of the impedanceangle with respect to angular frequency. Further, in a parallel RLCcircuit, the phase sensitivity G_(inv), is a function of both ω_(n) andQ.

Thus, to place an upper bound on the phase sensitivity G_(inv), amaximization process may be performed for G_(inv) with respect to ω_(n).$\begin{matrix}{\omega_{n} = {\omega\sqrt{\frac{2Q^{2}}{1 - {{6Q^{2}} \pm \sqrt{{32Q^{4}} - {12Q^{2}} + 1}}}}}} & (7)\end{matrix}$and thus $\begin{matrix}{{G_{inv\_ max}(Q)} = {\left\lbrack {\omega{\frac{\mathbb{d}\phi_{Island}}{\mathbb{d}\omega}}} \right\rbrack_{\max} = \frac{1}{2\sqrt{1 - {4Q^{2}}}}}} & (8)\end{matrix}$Further, for Q≧1/√{square root over (8)}, G_(inv)(ω_(n), Q) is maximizedwhen ω_(n)=ω and thus $\begin{matrix}{{G_{inv\_ max}(Q)} = {\left\lbrack {\omega{\frac{\mathbb{d}\phi_{Island}}{\mathbb{d}\omega}}} \right\rbrack_{\max} = {2Q}}} & (9)\end{matrix}$

FIG. 8 is a graph plotting equations (8) and (9). As illustrated in FIG.8, the maximum phase sensitivity is a substantially monotonic functionof the Q factor. Thus, to place an upper boundary on the maximum phasesensitivity, it is also necessary to find an upper boundary for the Qfactor of the aggregate islanded load. The other requirement for themaximum phase sensitivity is the load be resonant at the normaloperating frequency of the electric power system. In reality, thesituation represents a low power factor inductive load that has beencorrected to a unity power factor using power-factor compensationcapacitors. Further, the Q factor of the aggregate islanded load isbasically the ratio of the reactive power to real power in the inductiveload before compensation.

Therefore, to place an upper boundary on the Q factor, the lowest powerfactor likely to be encountered in an inductive load must be considered.A value of Q=2.5 appears to be an industry consensus value arrived at inthe development of IEEE 929, Recommended Practice for Utility Interfaceof Photovoltaic (PV) Systems. This value corresponds to a power factorof 0.37, which is a reasonable lower bound for an unloaded inductionmotor.

Thus, assuming an upper bound of Q=2.5, the maximum phase sensitivity isG_(inv) _(—) _(max) (Q)=5. The minimum frequency sensitivity to phaseangle variation G_(min) can then be defined as follows: $\begin{matrix}{G_{\min} = {\frac{1}{\left\lbrack {G_{inv\_ max}(Q)} \right\rbrack_{\max}} = {\frac{1}{2Q_{\max}} = \frac{1}{5}}}} & (10)\end{matrix}$Therefore, a lower bound on the percentage change in the frequency atthe POC for a given change in the current phase angle δ can bedetermined as follows: $\begin{matrix}\begin{matrix}{\frac{\Delta\quad f_{POC}}{f_{POC\_ n}} \approx {G\quad{\Delta\delta}\quad\frac{\Delta\quad f_{POC}}{f_{POC\_ n}}} \geq {G_{\min}\quad{\Delta\delta}\quad\frac{\Delta\quad f_{POC}}{f_{POC\_ n}}} \geq \frac{\Delta\quad\delta}{2Q_{\max}}} \\{\frac{\Delta\quad f_{POC}}{f_{POC\_ n}} \geq \frac{\Delta\quad\delta}{5}}\end{matrix} & (11)\end{matrix}$

-   -   where:    -   f_(POC) _(—) _(n) is the nominal line frequency at the point of        connection (Hz);    -   Δf_(POC) is the change in line frequency at the point of        connection (Hz); and    -   Δδ is the change in the generator system phase angle (radians).

Thus, in a perfectly matched stable generation island (of Q≦2.5), avariation in the generator system current phase angle of 0.1 radians(5.73°) will cause the frequency to change by at least 2%.

Therefore, according to the present invention, a small deliberatevariation in the generator system current phase angle can be utilized todetect a perfectly matched island by causing the frequency at the POC tovary outside the upper and lower frequency thresholds. The deliberate(active) variation may be applied periodically (for example, every 1second, etc.) or randomly. However, the variation should have asufficient low spectral content so as to pass through a low pass filterincluded within the control loop.

Further, the present invention advantageously provides a fasterdetection time over conventional devices because the current phase angleis actively varied, rather than actively varying the frequency. That is,the varied frequency shift has to be integrated into a phase shift andis thus slower than the detection method according to the presentinvention.

In addition, the required phase angle disturbance amplitude can becalculated from the upper and lower frequency thresholds as follows:$\begin{matrix}{{\Delta\quad\delta_{var}} \geq {5\frac{f_{over\_ trip} - f_{under\_ trip}}{f_{over\_ trip} + f_{under\_ trip}}}} & (12)\end{matrix}$where:

Δδ_(var) is the amplitude of the variation in the generator system phaseangle (radians);

f_(over) _(—) _(trip) is the upper frequency trip threshold (Hz); and

f_(under) _(—) _(trip) is the lower frequency trip threshold (Hz).

For example, for lower and upper frequency thresholds of 59.5 Hz and60.5 Hz, respectively, a current phase angle variation with an amplitudeof only 0.05 radians (2.86°) is sufficient to cause the frequency toexceed the lower and upper frequency thresholds in a perfectly matchedisland.

The present invention also provides a more sensitive method of detectinga perfectly matched island. In this method, a Rate Of Change OfFrequency (ROCOF) of the generator system output is measured incombination with the small variation in the generator system currentphase angle. In more detail, by using the ROCOF as a trip threshold, thevariation in the generator system phase angle does not have to perturbthe frequency in the island by enough to reach the lower and upperfrequency thresholds. Therefore, a smaller current phase angle variationcan be used.

The ROCOF protection feature according to the present invention is alsoadvantageously faster than the above-discussed lower and upper frequencythreshold protections. That is, if the changes in sign of the ROCOF areignored, a higher frequency perturbation in the generator system phaseangle can be used, which equates to a shorter detection time for aperfectly matched island.

In more detail, as noted above, φ_(island)=δ for a perfectly matchedisland. Combining this relationship with equation (2) results in thefollowing expression for the ROCOF caused by an active variation in thegenerator system current phase angle: $\begin{matrix}\begin{matrix}{{\frac{\mathbb{d}f_{POC}}{\mathbb{d}t}} = {f_{POC}G{\frac{\mathbb{d}\delta}{\mathbb{d}t}}}} \\{{\frac{\mathbb{d}f_{POC}}{\mathbb{d}t}} \geq {f_{POC}G_{\min}{\frac{\mathbb{d}\delta}{\mathbb{d}t}}}}\end{matrix} & (13)\end{matrix}$Further, a sinusoidal variation in the generator system current phaseangle of amplitude Δδ_(var) and frequency f_(δ) _(—) _(var) results in asinusoidal variation in the frequency at the POC. The ROCOF will alsoinclude a sinusoidal variation the amplitude of which is bounded by thebelow relationship: $\begin{matrix}{{{Amplitude}\left( \frac{\mathbb{d}f_{POC}}{\mathbb{d}t} \right)} \geq {\frac{2\Pi\quad f_{POC}}{5}{\Delta\delta}_{var}f_{\delta\_ var}}} & (14)\end{matrix}$

In addition, the minimum variation of the generator system current phaseangle required to detect a perfectly matched generation island throughan excessive ROCOF is as follows: $\begin{matrix}{{\Delta\quad\delta_{var}} \geq {\frac{5}{4f_{POC\_ n}f_{\delta\_ var}{G_{ROCOF}\left( f_{\delta\_ var} \right)}}{ROCOF}_{\lim}}} & (15)\end{matrix}$where:

-   -   Δδ_(var) is the amplitude of the variation in generator system        phase angle (radians);    -   f_(δ) _(—) _(var) is the frequency of the variation in the        generator system phase angle (Hz);    -   G_(ROCOF)(f_(δ) _(var)) is the gain of ROCOF measurement        circuit/algorithm at f_(δ) _(—) _(var);    -   f_(POC) _(—) _(n) is the nominal line frequency at the point of        interconnection (Hz); and    -   ROCOF_(lim) is the trip threshold on an average absolute value        of ROCOF (Hz/s).

For example, consider a generator system operating at a nominalfrequency of 60 Hz, and in which a generator system current phase anglevariation at 10 Hz and a ROCOF limit of 110 Hz/s is used. A typicalROCOF measurement gain at the variation frequency would be 0.71. In thiscase, a generator system current phase angle variation with an amplitudeof only 0.03 radians (1.7°) is sufficient to cause an excessive ROCOFtrip in a perfectly matched island.

Referring now to FIG. 9A, which is a flow chart illustrating theabove-noted detection methods according to the present invention (i.e.,actively varying the current phase angle and measuring the frequency orrate of change of the frequency). In addition, the steps illustrated inFIG. 9A may be executed via the components (such as a computer program,electric circuits, etc.) included in power controller 201 shown in FIG.2

The detection method of actively varying the current phase angle,measuring the output frequency, and comparing the measured frequency isillustrated by steps S2, S4, S8, S10, S12, S20, S22 and S24. In moredetail, the current phase angle is actively varied in step S20 and S24,and the angular frequency and phase are measured in steps S2 and S4. Themeasured frequency is then passed through a fast PLL in step S8 so as toremove noise and produce a clean frequency value which is compared withlower and upper frequency thresholds in steps S10 and S12, respectively.Note the actively varied current phase angle determined in steps S20 andS24 is the output current phase angle reference (shown in step S22) atthe output of power converter 206 shown in FIG. 2.

If the frequency value is less than the lower frequency threshold (Yesin step S10), a generation island is detected and the generator systemis commanded to stop the generator system from delivering electric powerto the electric power system. Otherwise, no fault is detected (No instep S10). Similarly, if the frequency value is greater than the upperfrequency threshold (Yes in step S12), a generation island is detectedand the generator system is commanded to stop delivering electric powerto the electric power system. Otherwise, no fault is detected (No instep S12).

The detection method of actively varying the current phase angle andmeasuring the rate of change of the output frequency (or the magnitudeof the rate of change of frequency) is illustrated by steps S2, S4, S8,S14 and S16, S20, S22 and S24. In more detail, the current phase angleis actively varied in steps S20 and S24, and the angular frequency andphase are measured in steps S2 and S4. The measured frequency is thenpassed through a fast PLL in step S8 so as to remove noise and produce aclean frequency signal. Further, the rate of change of the frequencyvalue is determined in step S14. An absolute value of the rate of changeof frequency is then compared with a predetermined threshold (10 Hz/s inFIG. 9A). If the absolute value of the rate of change of frequency isgreater than the predetermined threshold (Yes in step S16), a generationisland is detected and the generator system is connected to stopdelivering electric power to the electric power system. Otherwise, nofault is detected (No in step S16).

Turning now to yet another detection method according to the presentinvention. In this method, the steps S2, S4, S6, S8 and S18 areexecuted. In more detail, the angular frequency and phase are measuredin steps S2 and S4. The measured frequency is then passed through a slowPLL in step S6 and a fast PLL in step S8 so as to remove noise andproduce clean slow and fast phase angles, respectively.

In addition, it is noted both the fast PLL and the slow PLL have asufficient bandwidth to track real frequency changes within the electricpower system. Therefore, the angle and frequency estimates produced byboth PLLs are near identical when the generator system is operating inparallel with synchronous generators in the electric power system.However, when an unstable generation island is formed, the fast PLLrapidly changes in angle and frequency. Further, as shown in step S18,an absolute value of a phase shift between the fast and slow PLL iscompared with π/2. If the absolute value exceeds π/2, the generatorsystem will be commanded to stop energizing the POC and to initiate ashutdown (Yes in step S18). Otherwise, the generator system continues tooperate (No in step S18).

In addition, this phase-shift protective function provides coordinationbetween the anti-islanding protection in the generator system and highspeed reclosing of isolating devices in the electric power system. Thatis, by ensuring the phase-shift in the island is not more than π/2, anyvoltage transients that occur following an out of phase reclosure willnot be any greater than transients that occur during a reclosure into adead line. The phase-shift protection method according to the presentinvention therefore helps to ensure coordination with super high speedreclosing schemes used in the electric power system.

In still another example, as illustrated in FIG. 9B, the presentinvention provides a phase angle destabilization method used todestabilize islands that are otherwise stable. This method isillustrated by steps S2, S4, S6, S8, S22, S24, S26 and S28 in FIG. 9B.Note, this method can also be implanted with the ROCOF feature describedabove. In the example shown in FIG. 9B, the output current phase angleis increased whenever an increase in frequency is detected. To helpexplain how the phase-angle destabilization method operates, thegeneralized condition for a generation island to be stable is firstexamined. In more detail, when δ is time varying, the island will bestable if and only if: $\begin{matrix}{{{{\frac{\mathbb{d}\phi_{Island}}{\mathbb{d}\omega}}_{\omega = \omega_{0}} - \frac{\mathbb{d}\delta}{\mathbb{d}\omega}}}_{\omega = \omega_{0}} < 0} & (16)\end{matrix}$

Further, the demanded current phase angle δ can be defined as follows:δ=K _(active)(f _(fast) −f _(slow))  (17)

In addition, a perturbation on the frequency Δf_(POC) at the POC willresult in a perturbation in the fast PLL frequency, Δf_(fast), aperturbation in the slow PLL frequency, Δf_(slow), and a perturbation inthe output current phase angle, Δδ. In the time period between theresponse time of the fast PLL and the response time of the slow PLL,Δf_(fast)>>Δf_(slow) and thus the perturbation in the slow PLL frequencycan be ignored. This time period is of interest because the outputcurrent phase angle dynamics are governed by the response time of thefast PLL as follows:Δδ=K _(active)(Δf _(fast) −Δf _(slow))≈K _(active) ·Δf _(fast)  (18)

Further, f_(fast)=f_(POC) because the fast PLL is used to operate thecurrent control method. Thus, substituting this expression into equation(18), it is evident that in the time period of interest, the currentphase angle variation with frequency at the POC is governed by thefollowing equation: $\begin{matrix}{\frac{\mathbb{d}\delta}{\mathbb{d}\omega} \approx \frac{\Delta\delta}{2{\Pi \cdot \Delta}\quad f_{POC}} \approx \frac{K_{active}}{2\Pi}} & (19)\end{matrix}$

Further, as noted above in equation (9), for Q≧1 √{square root over(8)}: $\begin{matrix}{{\frac{\mathbb{d}\phi_{Island}}{\mathbb{d}\omega}}_{\omega = \omega_{0}} \leq \frac{2Q}{\omega}} & (20)\end{matrix}$Thus, the combination of equations (16), (19) and (20) establishes arelationship that determines the minimum value of K_(active) to ensurethat all islands up to a given Q factor will be destabilized by theactive phase angle destabilization method as follows: $\begin{matrix}{K_{active} > \frac{2Q}{f_{POC\_ n}}} & (21)\end{matrix}$

Further, in this example, the active frequency shift gain setting isKactive≈0.3. This ensures islands with Q factors of 7.5 or less will beunstable and therefore rapidly detected at nominal line frequencies ofboth 50 Hz and 60 Hz. The time between the creation of the islandsupported by the generator system and the time at which the generatorsystem detects the island and stops energizing the electric power systemis typically less than 10 cycles. This performance meets and exceeds therequirements of IEEE 929.

In addition, the ability of the active phase angle destabilizationmethod to destabilize a generation island is not adversely affected bythe presence of other anti-islanding distributed resources containedwithin the island. Indeed, many other distributed resource types usecompatible active frequency shift techniques and all of these systemswill act together to destabilize the island.

Further, as discussed above, the Rate Of Change Of Frequency (ROCOF) andphase shift protection functions may be used in conjunction with activephase angle destabilization algorithm according to the presentinvention. This combined scheme is compatible with other destabilizinganti-islanding schemes.

Turning now to FIG. 9B for a further detailed explanation of thedestablization method according to the present invention. As shown, theoutput frequency characteristic of the generator system is measured insteps S2 and S4, a first phase angle and frequency of the measuredfrequency characteristic is estimated using a first phase locked loophaving a first bandwidth in step S6, and a second phase angle andfrequency of the measured frequency characteristic is estimated using asecond phase locked loop having a second bandwidth greater than thefirst bandwidth in step S8. Further, the method calculates a frequencydifference between the first and second estimated frequencies in stepS28, and calculates an angle variation that is proportional to thecalculated frequency difference in step S26. The estimated second phaseangle is then added to the calculated angle variation in step S24 so asto form an output current phase angle reference. In addition, the outputcurrent phase angle of the generator system is controlled to be alignedwith the output current phase angle reference in step S22. The methodalso determines whether or not the generator system is within ageneration island based on the measured frequency characteristic (e.g.,by using the ROCOF and frequency detection method discussed above withreference to FIG. 9A).

Further, the detection methods according to the present invention candetect generation islands in less than one second. This is a significantimprovement over conventional detection method.

Additionally, the response time for the anti-islanding detection basedon the above-discussed under frequency, over frequency, excessive ROCOFand excessive phase-shift protective functions is affected by the needto reject swings in frequency or in the voltage phase angle that occurin normal operation at the POC. For generator systems swings in thevoltage phase angle are likely to be the most significant.

For example, consider the case illustrated in FIG. 10. In this example,an electric power system 400 including source of generation 401 iscoupled to site 402. Site 402 includes transformer 410, generator system412 and two loads 404, 406. Load 406 is connected to transformer 410 viaswitch 408. Due to impedances contributed to by source of generation 401and transformer 410, the voltage phase angle at POC 414 swings each timeswitch 408 is opened or closed. Further, if load 406 is a constantresistive load, the phase swing will be of the order of 0.075 radians.If load 406 is a filament lighting load with an inrush current of 10times the steady state load, the phase swing when switch 408 is closedcan be as high as 0.64 radians. $\begin{matrix}\begin{matrix}{T_{uf\_ trip} > \frac{\theta_{swing\_ max}}{2{\Pi\left( {f_{op\_ min} - f_{under\_ trip}} \right)}}} \\{T_{of\_ trip} > \frac{\theta_{swing\_ max}}{2{\Pi\left( {f_{over\_ trip} - f_{op\_ max}} \right)}}}\end{matrix} & (22)\end{matrix}$

In addition, over a short enough measurement period, a swing in thevoltage phase angle is indistinguishable from a change in frequency.Accordingly, the trip times for the under frequency, over frequency andROCOF thresholds must be long enough to prevent nuisance trips due tomisinterpretation of swings in the voltage phase angle as frequencydeviations. Suitable lower bounds can be placed on the trip times oncethe minimum normal operating frequency, maximum normal operatingfrequency and trip thresholds are known. That is, the followingequations may be used to determine these limits:

where:

θ_(swing) _(—) _(max) is the maximum anticipated swing in voltage phaseangle (radians);

f_(under) _(—) _(trip) is the under frequency trip threshold (Hz);

f_(over) _(—) _(trip) is the over frequency trip threshold (Hz);

f_(op) _(—) _(min) is the minimum operating frequency without nuisanceunder frequency trips (Hz);

f_(op) _(—) _(max) is the maximum operating frequency without nuisanceover frequency trips (Hz);

T_(uf) _(—) _(trip) is the under frequency trip time(s); and

T_(of) _(—) _(trip) is the over frequency trip time(s).

Generally, in an operational system, voltage phase angle swings inexcess of an eighth of a cycle are unlikely (θ_(swing) _(max)=π/4).Thus, to prevent nuisance trips with this size of phase swing for asystem operating at least 0.5 Hz away from the under frequency or overfrequency trip thresholds, the trip times must be at least 0.25 seconds.Accordingly, the under frequency and over frequency protection triptimes are preferably set to a minimum of 0.25 seconds (where electricpower system interconnection rules permit).

The ROCOF protection method provided by the present invention is alsosensitive to nuisance trips caused by voltage phase angle swings.Further, the ROCOF protective functions provided in the generator areset up to reject phase angle swings of up to π/4. The phase-shiftprotection is set to trip at a phase difference of π/2 and will thus beable to reject the phase angle swings associated with sudden loadchanges.

In addition, the magnitude and frequency of the generator system phaseangle variation, the response time of the ROCOF measurement method, theROCOF trip threshold and trip time affect the time taken to detect aperfectly matched generation island. Accordingly, these variables arepreferably coordinated to ensure that the anti-islanding protection iseffective and rapid without introducing the possibility of nuisancetrips.

In addition, the method of anti-islanding protection depends oncoordination of internal dynamic variables associated with the generatorsystem phase angle control, the PLL and the protection. The method isalso invariant from one electric power system to another. Therefore, thesettings associated with the selected method of anti-islandingprotection are preferably not adjustable.

Further, a preferred method of verifying the proper anti-islandingoperation is to test an example of the generator system operating in aperfectly matched island with a Q factor of 2.5.

Also, as noted above, the present island detection and anti-islandingprotection methods correspond to a generator system such as theMICRO-TURBINE connected to a utility grid. The present invention alsoapplies to other generation types employing closed-loop control ofoutput current magnitude and phase-angle, such as electronic powerconverter output based generators and synchronous generators withappropriate control of shaft speed and excitation voltage.

The present invention also relates to a computer program product forimplementing the detection and anti-islanding methods discussed above.Accordingly, this invention may be conveniently implemented using aconventional general purpose digital computer or microprocessorprogrammed according to the teachings of the present specification, aswill be apparent to those skilled in the computer art. Appropriatesoftware coding can readily be prepared by skilled programmers based onthe teachings of the present disclosure, as will be apparent to thoseskilled in the software art. The invention may also be implemented bythe preparation of application specific integrated circuits or byinterconnecting an appropriate network of conventional componentcircuits, as will be readily apparent to those skilled in the art.

The present invention includes a computer program product which is astorage medium including instructions which can be used to program acomputer to perform a process of the invention. The storage medium caninclude, but is not limited to, an type of disk including floppy disks,optical disks, CD-ROMs, and magneto-optical disks, ROMs, RAMs, EPROMs,EEPROMs, magnetic or optical cards, or any type of pure softwareinventions (e.g., word processing, accounting, Internet related, etc.)media suitable for storing electronic instructions.

Obviously, numerous modifications and variations of the presentinvention are possible in light of the above teachings. It is thereforeto be understood that within the scope of the appended claims, theinvention may be practiced otherwise than as specifically describedherein.

1. A method of controlling a generator system connected to an electricpower system, comprising: measuring an output frequency characteristicof the generator system; estimating a first phase angle of the measuredfrequency characteristic using a first phase locked loop having a firstbandwidth; estimating a second phase angle of the measured frequencycharacteristic using a second phase locked loop having a secondbandwidth greater than the first bandwidth; calculating a phase shiftbetween the estimated first and second phase angles; and determiningwhether or not the generator system is within a generation island basedon the calculated phase shift.
 2. The method according to claim 1,further comprising: stopping the generator system from deliveringelectric power to the electric power system if the determining stepdetermines the generator system is within a generation island.
 3. Themethod according to claim 1, wherein the determining step determines thegenerator system is within a generation island if an absolute value ofcalculated phase shift is greater than a predetermined threshold.
 4. Themethod according to claim 3, wherein the predetermined threshold is π/2.5. The method according to claim 1, wherein the first and secondbandwidths are approximately 1 Hz and 10 Hz, respectively.
 6. The methodaccording to claim 1, wherein the determining step determines whether ornot the generator system is within a generation island in less than 1second.
 7. A system for controlling a generator system connected to anelectric power system, comprising: means for measuring an outputfrequency characteristic of the generator system; means for estimating afirst phase angle of the measured frequency characteristic using a firstphase locked loop having a first bandwidth; means for estimating asecond phase angle of the measured frequency characteristic using asecond phase locked loop having a second bandwidth greater than thefirst bandwidth; means for calculating a phase shift between theestimated first and second phase angles; and means for determiningwhether or not the generator system is within a generation island basedon the calculated phase shift.
 8. The system according to claim 7,further comprising: means for stopping the generator system fromdelivering electric power to the electric power system if thedetermining means determines the generator system is within a generationisland.
 9. The system according to claim 7, wherein the determiningmeans determines the generator system is within a generation island ifan absolute value of calculated phase shift is greater than apredetermined threshold.
 10. The system according to claim 9, whereinthe predetermined threshold is π/2.
 11. The system according to claim 7,wherein the first and second bandwidths are approximately 1 Hz and 10Hz, respectively.
 12. The system according to claim 7, wherein thedetermining means determines whether or not the generator system iswithin a generation island in less than 1 second.
 13. In a generatorsystem connected to an electric power system, the improvementcomprising: a measuring circuit configured to measure an outputfrequency characteristic of the generator system; a first phase lockedloop having a first bandwidth and configured to estimate a first phaseangle of the measured frequency characteristic; a second phase lockedloop having a second bandwidth greater than the first bandwidth andconfigured to estimate a second phase angle of the measured frequencycharacteristic; a calculating circuit configured to calculate a phaseshift between the estimated first and second phase angles; and adetermining circuit configured to determine whether or not the generatorsystem is within a generation island based on the calculated phaseshift.
 14. The system according to claim 13, further comprising: adisconnecting circuit configure to stop the generator system fromdelivering electric power to the electric power system if thedetermining circuit determines the generator system is within ageneration island.
 15. The system according to claim 13, wherein thedetermining circuit determines the generator system is within ageneration island if an absolute value of calculated phase shift isgreater than a predetermined threshold.
 16. The system according toclaim 15, wherein the predetermined threshold is π/2.
 17. The systemaccording to claim 13, wherein the first and second bandwidths areapproximately 1 Hz and 10 Hz, respectively.
 18. The system according toclaim 13, wherein the determining circuit determines whether or not thegenerator system is within a generation island in less than 1 second.